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September 19, 2024

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Report Finds Mass. Storage Programs Falling Short on Equity

While Massachusetts has some of the strongest incentives for storage resources in the country, its programs are lagging in their focus on equity and environmental justice, according to a new report commissioned by the Clean Energy Group.  

The report analyzed the equity provisions in three Massachusetts programs that incentivize storage resources: the Clean Peak Energy Standard, the ConnectedSolutions program and the Solar Massachusetts Renewable Target (SMART) program. 

The report found that “the current energy storage-incentivizing programs in Massachusetts, while they are groundbreaking in many ways, do not live up to the commonwealth’s clean energy equity commitments.” 

It noted that the ConnectedSolutions program, which is part of the state’s utility-run energy efficiency program, and the Clean Peak Energy Standard lack incentives for deploying storage in low-income households or environmental justice neighborhoods and also do not include reporting requirements regarding equity.  

The SMART program, which focuses on boosting solar resources but also includes an incentive for co-located storage, does include additional incentives for low-income customers. However, data from the program indicate just 1.4% of SMART storage projects used this low-income adder. 

Todd Olinsky-Paul, senior project director at the Clean Energy Group, said he was surprised to find that not only is there no equity requirement, there’s no reporting requirement for two of the three programs. 

He emphasized the importance of including low-income households in the early stages of storage deployment and said low-income households often experience the most significant benefits of behind-the-meter storage resources.  

As climate change drives increased threats from extreme weather to the grid, the underserved communities are “getting hit the hardest,” Olinsky-Paul said.  

Because low-income households typically are the hardest to reach when deploying new technologies, it makes sense to prioritize these groups from the outset, Olinsky-Paul said. “Once you figure that out, then you’ll know how to get it to everybody else,” he added. 

The report is intended to influence the state’s ongoing work to update each of the programs, Olinsky-Paul noted. 

Commissioner Elizabeth Mahony of the Massachusetts Department of Energy Resources (DOER) told NetZero Insider the state plans to include an increased focus on equity in all three programs. 

“We’re in the infancy — or maybe toddler years — of the storage industry, and so our programs that work with storage deployment are in a similar phase,” Mahony said.  

The state issued a straw proposal in July for its update to the SMART program and proposed to increase the eligibility of low-income customers and require that community-shared solar programs enroll at least 40% low-income customers. 

The state also is working with the electric distribution companies (EDCs) to finalize their energy efficiency plans for the 2025/27 period, which will include updates to ConnectedSolutions. 

Regarding the Clean Peak standard, Mahony said the state is finishing updates focused on ratepayer protection and plans to address equity “in the next phase of that program.” 

Mahony noted that the state updated the Clean Peak standard in July to add “a near-term multiplier so that projects that are ready to go and can interconnect by 2027 … will get additional funding.” 

The DOER commissioner added that Gov. Maura Healey’s recently proposed closeout supplemental budget would direct a procurement of up to 5,000 MW. (See Mass. Gov. Healey Includes Permitting Reform in Budget Proposal.) The supplemental budget proposal also includes major reforms to the state’s permitting and siting processes, which Mahony called “our top topic.”

She said the state also is preparing a new $50 million storage grant program “that we hope to launch in some form later this year.” 

The legislature in 2018 established a goal for the state to deploy 1,000 MWh of energy storage by the end of 2025. In February, electric utilities reported the state has reached 569 MWh of installed storage, with 8,806 MWh in the development pipeline.  

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New Western Tx Could Bring Big CO2 Benefits, Study Shows

Carbon dioxide emissions from the Western U.S. power sector could drop by 73% from 2005 levels if 12 transmission projects in the development pipeline are finished by 2030, according to a new study from the U.S. Department of Energy.  

The report’s model incorporates 12 future transmission projects, which collectively span about 3,000 miles, and the likely wind and solar power projects and battery storage systems that would take advantage of the new capacity. The scenario “shows a reduction of CO2 emissions by 73% relative to 2005, reaching to 27% CO2 emissions in 2030,” according to the report published by the DOE’s Pacific Northwest National Laboratory on Sept. 13. 

“This work is important because it shows that significant progress can be made [toward] decarbonization policy objectives if we proceed with already-planned transmission projects to meet new capacity needs with new renewable resources,” Nader Samaan, report co-author and chief power systems research engineer at PNNL, told RTO Insider in an email. 

The report said more transmission could lead to renewable energy replacing some large thermal fossil generation, with the highest emissions reductions occurring in Utah, Nevada, Wyoming, Colorado, Arizona and New Mexico. 

“As of July 2024, the Western Interconnection hosts 30 gigawatts of wind power, 38 GW of solar power and 14 GW of energy storage,” the study said. “The report’s scenario would add an additional 35 GW of wind, 31 GW of solar and 12 GW of energy storage by 2030.” 

The 12 transmission projects behind the model include the 500-kV Boardman-to-Hemingway line, the Gateway West project and the Southwest Intertie Project-North, among others. (See DOE Awards $371M to Regulators, Communities Grappling with New Tx.) 

Aside from the purported environmental advantages, the transmission projects could also decrease generation costs by 32% compared with a reference case in which the projects were not built. However, “capital costs for generation and transmission are not considered as part of this analysis and would be needed for a complete economic evaluation,” according to the report. 

“Most of the infrastructure upgrades selected are either in interconnection queues or the transmission planning pipeline, increasing the likelihood that they will be realized,” the report stated. “In other words, the projects selected in this analysis rely implicitly on some economic analysis conducted by those proposing the projects.” 

The model also predicts a 26% reduction in California’s annual net energy imports from the Northwest. Under the scenario, the state could tap into “newly integrated wind resources from areas with abundant wind, such as Wyoming and New Mexico,” according to the report. This would also provide congestion relief for the Northwest, the report added. 

The report is part of the DOE-funded National Transmission Planning Study, slated to come out this year. 

“The upcoming National Transmission Planning study will expand on the possible transmission buildouts that could help the nation reach higher decarbonization goals,” Samaan said. 

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MIT Report Proposes Policies to Grow Use of Advanced Transmission Technologies

Advanced transmission technologies (ATTs) can help utilities meet the rising levels of demand that are stressing the grid, according to a report released Sept. 17 by the Massachusetts Institute of Technology’s Center for Energy and Environmental Policy Research (CEEPR).

ATTs are a suite of technologies that include grid-enhancing technologies (GETs). The most widely used ones are dynamic line ratings, advanced power flow control devices, topology optimization and high-performance conductors.

“Increased use of advanced transmission technologies can play a major role in meeting this demand growth quickly and cost-effectively,” the report says. “However, electricity market structures — which disincentivize investment in innovation — are impeding progress towards modernizing the electric grid.”

“A Roadmap for Advanced Transmission Technology Adoption” was written by Grid Strategies President Rob Gramlich, along with CEEPR Fellow Brian Deese and Research Associate Anna Pasnau, both of whom previously worked at the White House for President Joe Biden.

The technologies have been used for decades and are more widely deployed abroad. In the U.S., the lack of incentives for transmission providers, information provided to regulators and some features of electricity markets hold them back, according to the report. The profit structure of electricity markets does not offer the right incentives for transmission providers to adopt many forms of ATTs, despite their consumer benefits and the ability to quickly add transmission capacity to the grid, it says.

“Under the current electricity industry regulatory structure, utilities earn profits from capital expenditures, meaning that they are incentivized to make more costly capital investments (e.g., building a new power plant) over changing their operating expenses or lowering and smoothing demand for electricity — even when those capital expenditures ultimately increase costs for consumers,” the report says.

The “capex bias” is an accepted and well-known feature of cost-of-service regulation, according to the report. It disincentives utilities from deploying GETs because they would avoid the need to invest in new transmission — cutting their capital expenditures and thus their profits. Part of regulators’ job is to prevent utilities from taking advantage of that bias and ensure investments are in line with consumer interests, the report says.

“However, both transmission providers and regulators can struggle to identify the best way to expand capacity against a backdrop of multiple options, and for some technologies, they need new modeling practices to assess benefits,” the report says. “Transmission providers and their regulators have historically focused their cost-benefit analyses on a narrow set of risks and thus are slow to scale innovations, preferring the status quo.”

Some policies around ATTs have already improved, with states passing laws aimed at encouraging them, the report notes. Other policies have sought to align utility incentives with key performance metrics; FERC Order 1920 requires transmission providers to consider ATTs in the planning process.

Those steps are in the right direction, but the paper proposes five more to spread the use of ATTs across the grid:

    • Regulators should require the use of ATTs in certain contexts, with the paper suggesting FERC require DLRs on highly congested lines to increase their capacity at one-tenth the cost of reconductoring. The Department of Energy should adopt a national conductor efficiency standard, which would ensure utilities use more efficient lines that can cut line losses by 30%.
    • Transmission providers and regulators should have to conduct robust analyses of the value of ATTs for the electric grid. Order 1920 requires they be considered, but it lacks specificity on how robust of an analysis will be required. The paper suggests states adopt laws requiring more stringent analyses to complement the FERC rule.
    • FERC should create financial incentives for transmission providers to adopt ATTs where they provide high benefits. The commission should adopt a shared-savings incentive nationally, giving utilities a cut of ratepayer savings from GETs adoption, and where possible state legislators should authorize additional returns on equity for ATT investments.
    • The commission should require transmission providers to share additional information publicly so third parties can evaluate ATT adoption and hold utilities accountable when they fail to make sensible investments.
    • FERC should open up the planning process for a third party to work on deploying ATTs. The paper suggests the commission could require transmission providers to release relevant data to the National Renewable Energy Laboratory, or another qualified nonprofit entity, to come up with plans for each grid operator to adopt ATTs and update them on a regular basis.
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MISO, Monitor at Stalemate over Need for $21B Long-range Tx Plan

INDIANAPOLIS — MISO’s quarterly public meetup with its board of directors put on display the unrelenting rift between the RTO’s planners and the Independent Market Monitor over MISO’s $21 billion in upcoming long-range transmission planning.  

At a Sept. 17 Markets Committee meeting of the MISO Board of Directors, MISO IMM David Patton encouraged a recess on the proposed $21 billion second long-range transmission plan (LRTP) portfolio until MISO agrees to rework its 20-year view of its system and the benefit estimation of the transmission.  

Patton repeated concerns he raised earlier at a stakeholder workshop on MISO’s second LRTP portfolio, which MISO hopes to advance for board approval by the end of 2024. (See MISO Says 2nd Long-range Tx Plan to Cost $21B, Deliver Double in Benefits.) 

“We should pause this process and get to the bottom of this before we allow it to move on,” Patton told board members. “The problem is we don’t have a credible, ‘what-will-the-world-look-like’ scenario if we don’t build this transmission.”  

Senior Vice President of Planning and Operations Jennifer Curran said MISO believes it has devised a valuable portfolio and stands by its conservative, 1.9:1 benefit-to-cost estimate.  

“I think we have a different philosophy on benefits that leads to a fundamental disagreement,” she told the board.  

“We can’t perfectly predict the future. But through the use of scenarios, we can develop the most robust portfolio using the modeling we have available today,” Vice President of System Planning Aubrey Johnson said.  

Johnson said the LRTP can be interpreted as “skating to where the puck will be.” He said recent load growth shows MISO’s top-end, most radical planning scenario is likely, when some stakeholders thought it outlandish five years ago.  

Johnson said even scaling back MISO’s decarbonization benefit for areas of the footprint where the value of decarbonization isn’t openly acknowledged, the portfolio still would have 1.3:1 benefit-cost ratio.  

Multiple stakeholders urged MISO not to entertain the IMM’s request for an assumptions and benefits rework.  

ITC’s Brian Drumm said MISO leadership should reject the Monitor’s calls to “develop and test against an alternate reality” regarding LRTP transmission planning.  

Drumm said it’s “irresponsible and dangerous” for Patton to assume MISO won’t experience a major load shed event simply because it never has or assume members will make plans independently to dodge one.  

“Stakeholders have chosen to solve the reliability imperative through long-range planning and particularly” the second LRTP portfolio, Drumm argued. “The IMM’s request is inappropriate because MISO’s role is to plan regional transmission, not to serve as an integrated resource planner.”  

Drumm added that the industry is aware that significant loss of load events will occur again and become more pronounced by extreme weather. He said avoiding just one widespread load shedding event can more than cover the $21 billion price tag of LRTP II.  

The Union of Concerned Scientists’ Sam Gomberg said MISO isn’t going far enough in incorporating climate risk assessments in long-range transmission planning. He said the RTO should anticipate changing weather patterns to inform system planning so it doesn’t end up trying to solve the challenges of extreme weather on the fly in the control room.  

Gomberg also said MISO is correct to value decarbonization in transmission planning. He said Patton’s argument that federal production tax credits already fully value decarbonization and MISO’s benefit metric is redundant “borders on absurd” and gives too much credit to Congress to objectively put a price on the social cost of carbon.  

MISO Director Phyllis Currie asked if the RTO has a stance on planning for increased climate impacts on the system.   

“I think our primary objective is to reflect our members’ objectives. We really follow the lead of our members [rather] than taking an independent view of climate change,” Curran said. However, Curran added that from an operations standpoint, MISO uses analytics and machine learning to forecast weather events that historically haven’t occurred.   

“David Patton consistently misunderstands the benefits of regional backbone lines … [and] doesn’t like long-term scenario-based planning,” Sustainable FERC Project attorney Lauren Azar argued to board members. Azar said the IMM appears to want MISO to “go backwards” into the “balkanized system” that existed before the RTO’s creation.   

Azar rhetorically asked board members to place a monetary value on the 210 lives lost when the lights went out on Texas residents during Winter Storm Uri.  

Azar said the IMM should stick to its original purpose of “mainly markets” and advised MISO not to pay for the IMM’s opinions on transmission planning through its IMM budget.  

The MISO IMM has made some stakeholders uneasy with his interest in MISO’s long-range transmission planning and public criticism of the 20-year fleet and benefit estimates MISO uses. Since last year, some have said the IMM oversteps his role.  

MISO’s board of directors has included a $250,000 allowance in the Monitor’s $10 million budget next year to “monitor ratings and identify transmission withholding and compliance” associated with ambient adjusted line ratings requirements it will roll out under FERC Order 881. The line item and data collection of transmission data caused consternation among MISO transmission owners.  

MISO staff will be “actively discussing what data” transmission owners must provide, MISO Director Trip Doggett said.  

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DOE, PNNL Initiative to Focus on Equity in Tx Planning

Equity and community engagement have not been high priorities for the RTOs, ISOs, utilities and other organizations that have primary responsibility for planning the nation’s transmission system — a situation that historically has resulted in siting and permitting delays and, in some cases, yearslong litigation.

But the U.S. Department of Energy and Pacific Northwest National Laboratory (PNNL) want to change that narrative with a new initiative ― the Inclusive Transmission Planning (ITP) project ― which will provide technical assistance to grid planners seeking to integrate equity and community input into their projects up front, rather than as an add-on.

Speaking at a Sept. 17 webinar on the ITP, Emma Hibbard, a technical advisor in DOE’s Grid Deployment Office, laid out the rationale for the new program.

“Timely transmission deployment is essential to increase grid reliability and resilience and lower costs for consumers, as well as pave the way to a clean energy future, but often public acceptance of new transmission development can constrain [or] delay deployment,” Hibbard said. “There’s also an increasing awareness that positive outcomes for transmission development really hinge on ensuring positive and equitable outcomes for all, including disadvantaged and rural communities along transmission routes.”

Hibbard acknowledged that FERC, state regulators and many grid planners are working to improve transparency and public participation. But, she said, “there’s a need for more information and more support around energy equity and the relationship to transmission planning, and … new approaches to soliciting and integrating community input, in addition to what is already existing.”

The webinar provided an overview of the ITP program, which is offering two tracks of technical assistance — but no funding — for grid planning organizations.

“Tier 1 is really about education, outreach and capacity building,” said Paul Wetherbee, an advisor on regional energy system planning at PNNL. “We’re really talking about educating and building awareness of energy equity concepts” — for example, providing a presentation “describing the main pillars of energy equity and how they would fit into the transmission planning process, or how to think about that in terms of your existing transmission planning processes.”

In Tier 2, “we’re going to do a deep dive with the applicant into the pool and go into some of [the] details of other transmission planning processes and metrics,” Wetherbee said. Topics “might include developing quantitative energy equity metrics, putting that together with the existing data sets and working with the applicant to go through their current … transmission planning metrics” and cover energy equity measures.

Tier 2 could also look at how to integrate energy equity into cost allocation metrics and transmission economics, he said.

Both tracks will incorporate three components, said Jennifer Yoshimura, the principal investigator for the program at PNNL. A series of listening sessions will begin in October to gather input from a broad range of stakeholders “to understand opportunities for participation as well as barriers,” Yoshimura said. The listening sessions for transmission planners are scheduled for Oct. 1 and Oct. 16.

The ITP will also develop research and resource materials for the general public as well as grid planners “to increase inclusivity as well as equitable outcomes,” she said. The technical assistance component will focus on “capacity building for transmission planners to look at how to incorporate energy equity and justice objectives within their planning processes and paradigms.”

Applications for the program are now open, with a final deadline of Oct. 31, Wetherbee said. Applications will be reviewed in November, and program participants will be announced in December. Both tiers will kick off in January 2025 and run through November.

Eligibility is strictly limited to grid planning organizations, including RTOs, ISOs, utilities and power marketing administrations, such as the Bonneville Power Administration, but DOE and PNNL are looking for diverse participants for each tier, based on geography and equity issues, Wetherbee said.

Tribes often do not have dedicated grid planners, but DOE on Sept. 17 also announced a Tribal Nation Transmission Program, which will provide “educational resources, training and on-call assistance from technical experts and researchers from the National Renewable Energy Laboratory.”

‘We Didn’t Start with Equity’

The historic and ongoing challenges for new approaches to inclusive grid planning are complex, Yoshimura said in her opening remarks at the webinar.

Traditional industry metrics — such as the System Average Interruption Duration Index, or SAIDI — focus on “system averages that can hide vulnerabilities at the household level,” she said. “We see an increase of threats and vulnerabilities involved, whether individuals with ill intentions to harm substations or transmission lines [at risk from] increasing wildfires. …

“Within transmission planning processes, we have seen an emphasis and research focusing on integrated distribution planning, as well as energy transitions on the generation side,” she said. “But there are a lot of opportunities still needed to include equity and equity objectives within transmission planning” in ways that drill down to the granular, household level.

A question-and-answer session following the official presentation reflected some of the challenges ahead.

One participant asked if the ITP program would address ways to improve the National Environmental Policy Act process, the environmental reviews that can slow down and delay the siting and permitting of transmission projects.

Bethel Tarekegne, a PNNL research engineer, said whether the program would cover NEPA was still being discussed, while Yoshimura stressed that NEPA reviews are primarily part of siting and permitting processes, not planning. The Grid Deployment Office has other programs focused on siting and permitting, she said.

DOE and PNNL staff also were asked if they could provide any examples of transmission planning that resulted in equitable participation or outcomes, but none of them could.

“A lot of transmission today is really built around reliability, economics and public policy,” said Patrick Maloney, a power system engineer at PNNL. Lacking examples, he suggested that “allocation of costs might be thought of as a way to bring some equity into the transmission planning process.”

Yoshimura also came up empty on examples. “Our systems and institutions and policies, we didn’t start with equity, yet we’re trying to get to equitable outcomes,” she said. “And so, I think projects like this, listening sessions, case studies and how we learn from each other will help us move in the direction that we need.”

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NYISO Offers Final Staff Recommendations for Demand Curve Reset

NYISO presented its final interim staff recommendations for the demand curve reset for 2025-2029 at the Installed Capacity Working Group’s meeting Sept. 10, with minor updates to some metrics.  

The recommendations remain largely the same as the draft presented in August, with the two-hour battery energy storage system (BESS) as the representative lowest-cost peaker plant technology. (See NYISO Presents Draft Recommendations for Demand Curve Reset.) 

As part of calculating the cost of new entry for a hypothetical peaker plant, Zach Smith, senior manager of capacity and new resource integration for NYISO, said the ISO opted to factor in land lease payments for the construction period for the hypothetical peaker. Interconnection costs were modified downward across all zones outside of Long Island. The new derating factor for the BESS also was discussed. 

Smith said the interconnection costs were estimated to be higher because it was assumed peakers would require 345 kV, but 200-MW battery storage systems can connect to lower-voltage lines, which cost less. “And it appears to be better aligned with the actual interconnection requests that we are seeing,” Smith added.  

The Analysis Group, NYISO’s consultant on the reset, also updated net energy and ancillary services (EAS) revenues to account for an operator of a BESS plant maintaining their state of charge to meet day-ahead schedules. 

“The change here is that we force the battery to charge more before the peak load window,” said Paul Hibbard, principal of Analysis Group. 

Hibbard said the change causes negligible differences to net EAS revenue across all zones, aside from Long Island, which saw a 12% drop. 

Derating Factor Headaches

Smith said NYISO was recommending a 2.5% derating factor for BESS peakers. The derating factor was calculated as a weighted average of the derating factors that batteries should expect to receive across their 20-year amortization period. 

NYISO does not yet have a class average for BESS units. “The ICAP Manual (Section 4.5) currently establishes that the initial derating factor a new BESS would receive upon entering the ICAP market is based on the NERC class average equivalent demand forced outage rate (EFORd) of pumped hydro storage until three energy storage resources are participating in the ICAP market and have sufficient historical operating data to establish a ‘NYISO class average’ EFORd for energy storage resources,” the ISO said. 

The 2.5% derating factor is based on the assumption that any new BESS would have an initial 9.19% derating factor — the current class average for pumped hydro — for its first year of operation. The derating factor for the second year would be 5.6%, which is the average of 9.19% and 2%, which is the derating factor estimated by NYISO’s consultants. NYISO then assumes a 2% derating factor for years 3 to 20 of the estimated life of the battery. The average over those 20 years is about 2.5%. 

But this prompted questions from stakeholders. 

“I don’t understand how you can make this change without making companion changes to the manual,” said Doreen Saia, of Greenberg Traurig. “The unit that comes online next year isn’t going to get 2.5%. It’s going to get 9.19% unless and until we make changes to our actual rules.” 

Smith clarified the derating factor would be 9.19% for the first year and the average of the 9.19% and the actual availability of the BESS for the rest of its operating life. 

“A unit’s derating factor, once it has sufficient operating experience, is always based on its actual production,” Smith said. 

Open Questions, Open Frustrations

Smith went over several questions NYISO still was reviewing, such as how to take into account sales tax for BESS labor, operations and maintenance costs; investment tax credits for the transmission lines to the plants; and costs of debt and equity. 

Some stakeholders were unhappy that several longstanding questions were not answered and not addressed in the open questions. They said they wanted to see cost declines for battery units included in the analysis. 

“The ISO has recently shown the assumptions that it’s doing in the study with the Department of Public Service and the transmission owners, and it shows an expectation of more than a 50% decline in battery storage costs over the next 10 years,” said Mark Younger of Hudson Energy Economics. This meant a decline in revenues for the battery units; thus, NYISO’s net cost of new entry was about 45% too low. 

Another stakeholder was disappointed NYISO was not proposing to include revenues for BESS units that come from outside wholesale markets, which could include incentive programs from the state and utilities.  

“I think it severely overstates the net CONE of these facilities and therefore it will impose very high, unnecessary costs on New York consumers,” they said. 

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RTOs Seek More Flexible Compliance in Appeal of EPA Power Plant Rule

ERCOT, MISO, PJM and SPP last week filed a joint brief in the appeal of EPA’s power plant rule seeking more flexibility on compliance, arguing it is needed to ensure reliability. (See Republican-led States Sue EPA over Power Plant Emissions Rule.) 

The four grid operators submitted comments similar to those they made while the agency was working on the rule. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.) 

“Without additional modification, the compliance timelines and related provisions of the rule are not workable and are destined to trigger an acceleration in the pace of premature retirements of electric generation units that possess critical reliability attributes at the very time when such generation is needed to support ever-increasing electricity demand because of the growth of the digital economy and the need to ensure adequate backup generation to support an increasing amount of intermittent renewable generation,” they wrote. EPA’s final rule would strain their ability to maintain the reliability of the electric grid, they argued. 

The grid operators had proposed a “reliability safety valve” that would help mitigate their concerns, but EPA did not include that in the final rule, nor did it explain why, they noted. The grid operators had wanted EPA to provide upfront, clear criteria on the “remaining use of life and other factors” and enforcement discretion; the creation of a subcategory of generators needed for reliability; offering states guidance on how to use a reliability valve; and the creation of “regional reliability allowances” that generators could use in emergencies to avoid penalties under the rule. 

Instead, they argued, the final rule unreasonably discounts that existing fossil generators will need to decide whether to commit to installing untested technology or retire their units years before the compliance deadline with state compliance proposals due in 2026. That could accelerate earlier retirements of generators, the grid operators said. 

The rule requires 90% carbon capture and storage for coal plants that want to run after Jan. 1, 2039, as well as for new and modified natural gas units with capacity factors of 40% and above. Both categories of plants would need to install CCS systems by Jan. 1, 2032. 

“None of EPA’s projected time frames reflect historical rates of adoption of CCS technology for electrical generation purposes, nor does EPA adequately consider the risks that the technologies will not mature in time for [electric generating unit] owners to deploy them,” the grid operators said. 

EPA’s rule did include a short-term reliability mechanism, which requires the declaration of an energy emergency alert 2 before any compliance mitigation can take place. 

“This short-term reliability mechanism that EPA did adopt in the rule thus unduly places the grid — and customers — at greater risk before any short-term relief would be available,” the grid operators said. They “should not have to wait until the heightened level of emergency that an EEA2 declaration represents; they should be able to take proactive measures to address reliability issues upon earlier evidence of deteriorating grid conditions as evidenced by declaration of an energy emergency alert 1.” 

Compliance flexibility should kick in at EEA 1 because at that point, grid operators can still call on emergency generation. By waiting until an EEA 2, grid operators cannot act until they are in a real-time emergency. 

For longer-term issues, states can ask for extended deadlines or lower technology standards, but the grid operators would like to see EPA offer more guidance on that process. 

EPA is not responding to the initial briefs until next month, but the RTOs’ comments did generate some response from others. The Clean Air Task Force and Natural Resources Defense Council filed lengthy comments on grid reliability, arguing the rule was designed to give utilities and system operators the flexibility they need to maintain grid reliability. 

“While EPA has considered reliability issues in its proposal, FERC is the agency with direct jurisdiction over electric reliability,” the organizations said. “As discussed above and as recognized by FERC, the electric grid is undergoing changes unrelated to the EPA proposal, and the proposed regulations are only incremental to these existing forces. FERC and the electric utilities have the responsibility and many tools available to them to ensure reliability as these grid changes occur.” 

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Company Briefs

BP to Sell US Onshore Wind Business

BP last week announced it plans to sell its U.S. onshore wind energy business, saying the assets are not aligned with its growth plans. 

BP said it will launch the sale process for the wind assets, bp Wind Energy, which has interests in 10 operating assets across seven states. 

The move also comes as BP’s new CEO, Murray Auchincloss, has imposed a hiring freeze and paused new offshore wind projects. 

More: Reuters 

Google Signs PPA with X-Elio

Google last week announced a power purchase agreement with Spain-based renewables company X-Elio. 

Google will offtake all 128 MW from X-Elio’s Bell solar farm in Texas, which will also feature a 100-MW storage system. 

The farm is expected to be operational in the second half of 2025. 

More: Renewables Now 

AMS Renewable Energy Acquires Collective Solar

AMS Renewable Energy, a distributed solar and storage engineering, procurement and construction company, last week announced the acquisition of Collective Solar, a distributed generation solar construction firm. 

With the acquisition of Collective and its construction platform, AMS will now have the resources to scale design, engineering, logistics, procurement and construction services for its developer and clients. 

More: Solar Power World 

Vistra, Sunrun Partner on Residential Battery Aggregation Program

Vistra last week announced a new program will aggregate power stored in residential, solar-connected batteries, forming a virtual power plant to dispatch energy in times of high demand. 

TXU Energy customers who opt into the program and have installed Sunrun solar panels and batteries will receive incentives for their participation. In partnership with TXU Energy, Sunrun will network customers’ batteries together and manage the discharging of stored power. 

More: Vistra 

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Federal Briefs

EIA: US Power Use to Reach Record Highs in 2024, 2025

U.S. power consumption is on track to rise to new records in 2024 and 2025, according to the EIA. 

The administration projected demand will rise to 4.101 terawatt-hours (TWh) in 2024 and 4.185 TWh in 2025. That compares to 4 TWh in 2023 and a record 4.067 TWh in 2022. 

More: Reuters 

Man Pleads Guilty to Shooting Electricity, Pipeline Facilities

Cameron Monte Smith last week pleaded guilty in federal court to two counts of destruction of an energy facility, with one count each in North Dakota and South Dakota. 

Court documents show Smith caused more than $1.2 million in damage by shooting at the Wheelock substation in northwest North Dakota with a high-powered rifle in May 2023. Smith also caused more than $495,000 in damage to a transformer and pump station of the Keystone Pipeline in South Dakota in July 2022. 

Smith faces up to 20 years in prison for each count. 

More: South Dakota Searchlight 

Judge Temporarily Blocks Biden Rule to Limit Flaring at Oil Wells

U.S. District Judge Daniel Traynor last week temporarily blocked a new Biden administration rule aimed at reducing the venting and flaring of natural gas at oil wells. 

North Dakota, Montana, Texas, Wyoming and Utah challenged the rule earlier this year, arguing it would hinder oil and gas production and that the Bureau of Land Management overstepped its regulatory authority on non-federal minerals and air pollution. 

“At this preliminary stage, the plaintiffs have shown they are likely to succeed on the merits of their claim the 2024 rule is arbitrary and capricious,” Traynor wrote in his ruling. 

More: The Associated Press 

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State Briefs

COLORADO 

PUC Investigates Xcel over Power Outage Complaints

The Public Utilities Commission last week discussed how to move forward with its investigation of Xcel Energy over the numerous complaints about power outages. 

Erin O’Neill, deputy director of fixed utilities for the commission, said there are a lot of unanswered questions about what is causing the outages and how Xcel is responding. 

More: CPR News 

IOWA 

Republicans, Sierra Club File Lawsuits Against Summit Pipeline Decision

A group of nearly 40 lawmakers comprising the Republican Legislative Intervenors for Justice, along with the Sierra Club’s state chapter, last week said they plan to ask federal and state courts to rule that the Utilities Commission acted illegally and unconstitutionally in its approval of Summit Carbon Solutions’ pipeline. 

The pipeline “prioritizes corporate interests in tax credits over the safety, property rights and well-being of Iowa’s citizens,” according to a statement from the lawmakers. 

The Utilities Commission approved the application in June, under the conditions that Summit submitted documentation of various regulating requirements and an insurance policy. The $8 billion pipeline project would connect to 57 ethanol plants and stretch across Iowa, Nebraska, Minnesota, South Dakota and North Dakota. 

More: Iowa Capital Dispatch; Radio Iowa 

KENTUCKY 

Beshear Names Stacy to PSC

Gov. Andy Beshear last week named John Will Stacy, a state representative from 1993 to 2015, to the Public Service Commission. 

Stacy was House majority whip serving alongside then-House Speaker Greg Stumbo and then-House Majority Leader Rocky Adkins, who is now a senior adviser to Beshear. 

Stacy replaces Kent Chandler, the former chair, after he resigned in June. 

More: Kentucky Lantern 

MONTANA 

PSC to Investigate NorthWestern Energy Committee

The Public Service Commission last week voted to open an investigation into NorthWestern Energy’s Electric Technical Advisory Committee. 

This summer, three renewable energy groups raised questions about whether NorthWestern was legally running the committee, which makes recommendations about resource planning for the future. The groups said NorthWestern was closing its meetings to the public without adequate justification and hadn’t chosen members who represent broad interests. 

The investigation will allow the PSC to collect information and materials about the committee and post it on its public portal. 

More: Daily Montanan 

NEW YORK

Vestas Secures Empire Wind 1 Project Order

Vestas last week announced it has secured an 810 MW offshore order from Equinor to power the Empire Wind 1 offshore wind project. 

The order includes 54 V236-15.0 MW turbines and marks the company’s first U.S. order for an offshore platform and this type of turbine. 

Turbine delivery is expected to begin in 2026 with completion scheduled for 2027. 

More: North American Windpower 

NORTH CAROLINA

UC Staff Recommends Reducing VEPCO’s Proposed Rate Hike

Utilities Commission staff last week recommended a $28.6 million rate increase for Virginia Electric and Power Co. (VEPCO), about half of what the company originally requested. 

The recommended increase is premised on a 9.60% ROE, which is 15 points below the utility’s currently authorized ROE. It is also significantly below the 10.60% ROE requested by VEPCO. 

VEPCO has initially asked for a $56.6 million increase. 

More: S&P Global 

OHIO 

FirstEnergy to Pay $100M in HB 6 Settlement with SEC

FirstEnergy last week agreed to pay a $100 million fine to settle civil fraud charges filed by the Securities and Exchange Commission related to the House Bill 6 nuclear power plant bailout scandal. 

The utility’s former CEO, Charles Jones, will still face charges from the SEC, which is accusing him of misleading investors after former House Speaker Larry Householder was arrested in the $60 million bribery case in 2020. 

The SEC fine is significantly higher than FirstEnergy’s $20 million settlement with state prosecutors made a month ago. 

More: Statehouse News Bureau 

VIRGINIA 

Appalachian Power Requests Reduction to Net-metering Pay Rate

Appalachian Power on Aug. 30 submitted a request to the State Corporation Commission for a 70% reduction in its net-metering pay rate. 

Appalachian Power is currently paying participants 16 cents/kWh for the excess power they generate, and wants to grandfather them for 25 years, while offering new participants 4 cents/kWh. For a customer who needs about 1,000 kW and generates 1,057 kW through their panels, the change would result in a monthly bill increase from $7.96 to $66.95. 

The commission is expected to review the request over the next 12 months. 

More: Virginia Mercury 

Fairfax County to Regulate Data Center Construction

The Fairfax County Board of Supervisors last week voted 8-2 to put new restrictions on data centers and where they can be located. 

Where the centers are built has been controversial in many parts of the state, including Loudoun and Prince William counties. While Fairfax County has about 3 million square feet of data centers, Loudoun County has more than 30 million. 

The new regulations were passed after a four-hour public hearing. 

More: DC News Now 

TEXAS 

Golden Pass LNG Requests Extension from FERC

Golden Pass LNG on Aug. 28 requested a three-year extension from FERC to finish construction of its facility near Sabine Pass. 

The requested extension would give Golden Pass until Nov. 30, 2029, to finish the project. The request comes after Golden Pass LNG’s lead construction contractor, Zachry Holdings, was ordered to exit the project in July in an “efficient and cooperative manner” by a bankruptcy judge. 

Golden Pass has already been issued one extension by FERC on Dec. 11, 2019, until Nov. 30, 2026. 

More: Houston Chronicle